The production of hydrocarbons from a reservoir oftentimes carries with it the incidental production of non-hydrocarbon gases. Such gases include contaminants such as hydrogen sulfide (H2S) and carbon dioxide (CO2). When H2S or CO2 are produced as part of a hydrocarbon stream (such as methane or ethane), the raw gas stream is sometimes referred to as “sour gas.” The H2S and CO2 are often referred to together as “acid gases.”
In addition to hydrocarbon production streams, acid gases may be associated with synthesis gas streams, or with refinery gas streams. Acid gases may also be present within so-called flash-gas streams in gas processing facilities. Further, acid gases may be generated by the combustion of coal, natural gas, or other carbonaceous fuels.
Gas and/or hydrocarbon fluid streams may contain not only H2S or CO2, but may also contain other “acidic” impurities. These include mercaptans and other trace sulfur compounds (SOx). In addition, natural gas streams may contain water. Indeed, water is the most common contaminant in many natural gas streams. Such impurities should be removed prior to industrial or residential use.
Processes have been devised to remove contaminants from a raw natural gas stream. In the case of acid gases, cryogenic gas processing is sometimes used, particularly to remove CO2 to prevent line freezing and plugged orifices. In other instances, particularly with H2S removal, the hydrocarbon fluid stream is treated with a solvent. Solvents may include chemical solvents such as amines Examples of amines used in sour gas treatment include monoethanol amine (MEA), diethanol amine (DEA), and methyl diethanol amine (MDEA).
Physical solvents are sometimes used in lieu of amine solvents. Examples include physical solvents currently marketed under the brand names Selexol® (comprising dimethyl ethers of polyethylene glycol) and Rectisol™ (comprising methanol). In some instances hybrid solvents, meaning mixtures of physical and chemical solvents, have been used. An example of one such hybrid solvent is currently marketed under the brand name Sulfinol® (comprising sulfolane, water, and one or more amines). However, the use of amine-based acid gas removal solvents is most common.
Amine-based solvents rely on a chemical reaction with the acid gases. The reaction process is sometimes referred to as “gas sweetening.” Such chemical reactions are generally more effective than the physical-based solvents, particularly at feed gas pressures below about 300 pounds per square inch (psia) (2.07 megapascals (MPa)). There are instances where special chemical solvents such as Flexsorb® (comprising hindered amine) are used, particularly for selectively removing H2S from CO2-containing gas and/or hydrocarbon fluid streams.
As a result of the gas sweetening process, a treated or “sweetened” gas stream is created. The sweetened gas stream is substantially depleted of H2S and/or CO2 components. The sweetened gas can be further processed for liquids recovery, that is, by condensing out heavier hydrocarbon gases. The sweet gas may be sold into a pipeline or may be used for liquefied natural gas (LNG) feed. In addition, the sweetened gas stream may be used as feedstock for a gas-to-liquids process, and then ultimately used to make waxes, butanes, lubricants, glycols and other petroleum-based products. The extracted CO2 may be sold, or it may be injected into a subterranean reservoir for enhanced oil recovery operations.
When a natural gas stream contains water, a dehydration process is usually undertaken before or after acid gas removal. This is done through the use of glycol or other desiccant in a water separator. The dehydration of natural gas is done to control the formation of gas hydrates and to prevent corrosion in distribution pipelines. The formation of gas hydrates and corrosion in pipelines can cause a decrease in flow volume as well as frozen control valves, plugged orifices and other operating problems.
Traditionally, the removal of acid gases or water using chemical solvents or desiccants involves counter-currently contacting the raw natural gas stream with the chemical. The raw gas stream is introduced into the bottom section of a contacting tower. At the same time, the solvent solution is directed into a top section of the tower. The tower has trays, packing, or other “internals.” As the liquid solvent cascades through the internals, it absorbs the undesirable components, carrying them away through the bottom of the contacting tower as part of a “rich” solvent solution. At the same time, gaseous fluid that is largely depleted of the undesirable components exits at the top of the tower.
The rich solvent or rich glycol, as the case may be, that exits the contactor is sometimes referred to as an absorbent liquid. Following absorption, a process of regeneration (also called “desorption”) may be employed to separate contaminants from the active solvent of the absorbent liquid. This produces a “lean” solvent or a “lean” glycol that is then typically recycled into the contacting tower for further absorption.
While perhaps capable of performing desired contacting for removal of contaminants from a gas and/or hydrocarbon-containing fluid stream, historic contactor solutions have had difficulty scaling-up from lab and/or pilot-sized units to units capable of efficiently processing up to a billion standard cubic feet per day (BSFD) of gas. Past scale-up solutions have high capital expenses (e.g., due to having larger and more pieces of equipment, etc.) and high operational expenses (e.g., due to less reliability and/or operability, larger size and weight equipment, etc.). Consequently, a need exists for a contacting solution that is smaller, has fewer pieces of equipment, has improved operability and reliability, and weighs less than traditional contacting equipment.